<PAGE> 1
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A1
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 1998
Commission File Number: 33-74254
COGENTRIX ENERGY, INC.
(Exact name of registrant as specified in its charter)
North Carolina 56-1853081
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification Number)
9405 Arrowpoint Boulevard, Charlotte, North Carolina 28273-8110
(Address of principal executive offices) (Zipcode)
(704) 525-3800
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such period that the registrant was required to
file such reports), and (2) has been subject to such filing requirements for the
past 90 days. [X] Yes [ ] No
On November 16, 1998, there were 282,000 shares of common stock, no par value,
issued and outstanding.
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COGENTRIX ENERGY, INC.
Page No.
--------
Part I: Financial Information
Item 1. Consolidated Condensed Financial Statements:
Consolidated Balance Sheets at September 30, 1998 (Unaudited)
and December 31, 1997 3
Consolidated Statements of Income for the Three Months
and Nine Months Ended September 30, 1998 and 1997 (Unaudited) 4
Consolidated Statements of Cash Flows for the Nine Months
Ended September 30, 1998 and 1997 (Unaudited) 5
Notes to Consolidated Condensed Financial Statements (Unaudited) 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 10
Signatures 19
2
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COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
September 30, 1998 and December 31, 1997
(dollars in thousands)
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
---------- ---------
(Unaudited) (Audited)
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 29,638 $ 71,833
Restricted cash 53,688 27,742
Marketable securities -- 42,118
Accounts receivable 65,718 49,781
Inventories 19,869 15,210
Other current assets 3,875 2,465
---------- --------
Total current assets 172,788 209,149
NET INVESTMENT IN LEASES 497,966 --
PROPERTY, PLANT AND EQUIPMENT, net of accumulated
depreciation: September 30, 1998, $216,415; December 31, 1997, $188,227 480,077 496,589
LAND AND IMPROVEMENTS 3,574 2,540
DEFERRED FINANCING AND ORGANIZATION COSTS,
net of accumulated amortization: September 30, 1998, $13,414;
December 31, 1997, $16,592 31,218 21,085
NATURAL GAS RESERVES 1,748 2,384
INVESTMENTS IN UNCONSOLIDATED AFFILIATES 72,846 79,072
OTHER ASSETS 47,053 12,155
---------- --------
$1,307,270 $822,974
========== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt $ 77,641 $ 74,680
Accounts payable 26,244 13,755
Accrued compensation 5,893 4,923
Accrued interest payable 7,930 2,935
Accrued dividends payable -- 2,140
Other accrued liabilities 15,449 8,182
---------- --------
Total current liabilities 133,157 106,615
LONG-TERM DEBT 960,621 595,112
DEFERRED INCOME TAXES 37,004 25,872
MINORITY INTERESTS 60,728 15,131
OTHER LONG-TERM LIABILITIES 23,529 21,946
---------- --------
1,215,039 764,676
---------- --------
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY:
Common stock, no par value, 300,000 shares authorized;
282,000 shares issued and outstanding 130 130
Net unrealized gain on available for sale securities -- 26
Accumulated earnings 92,101 58,142
---------- --------
92,231 58,298
---------- --------
$1,307,270 $822,974
========== ========
</TABLE>
The accompanying notes to consolidated condensed financial statements
are an integral part of these consolidated balance sheets.
3
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COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months and Nine Months Ended
September 30, 1998 and 1997 (Unaudited)
(dollars in thousands, except for earnings per common share)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
1998 1997 1998 1997
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
OPERATING REVENUE:
Electric $ 84,832 $ 82,358 $ 231,200 $ 234,652
Steam 5,620 6,049 19,325 19,451
Lease revenue 11,134 -- 23,567 --
Service revenue under capital leases 12,703 -- 25,955 --
Income from unconsolidated investments in power projects 829 397 2,626 623
Other 7,554 2,728 14,855 8,463
--------- --------- --------- ---------
122,672 91,532 317,528 263,189
--------- --------- --------- ---------
OPERATING EXPENSES:
Fuel expense 23,576 31,199 62,500 91,254
Operations and maintenance 17,309 16,696 49,581 52,739
Cost of services under capital leases 14,019 -- 29,358 --
General, administrative and development expenses 8,613 8,139 27,765 31,547
Depreciation and amortization 10,767 10,238 31,382 31,583
--------- --------- --------- ---------
74,284 66,272 200,586 207,123
--------- --------- --------- ---------
OPERATING INCOME 48,388 25,260 116,942 56,066
OTHER INCOME (EXPENSE):
Interest expense (18,908) (13,253) (51,993) (41,419)
Investment and other income, net 1,304 1,923 5,169 7,378
Equity in net loss of affiliates, net (3,157) (593) (3,242) (410)
--------- --------- --------- ---------
INCOME BEFORE MINORITY INTERESTS IN INCOME,
INCOME TAXES AND EXTRAORDINARY LOSS 27,627 13,337 66,876 21,615
MINORITY INTERESTS IN INCOME BEFORE
EXTRAORDINARY LOSS (4,187) (1,364) (9,800) (3,763)
--------- --------- --------- ---------
INCOME BEFORE INCOME TAXES AND
EXTRAORDINARY LOSS 23,440 11,973 57,076 17,852
PROVISION FOR INCOME TAXES (8,969) (4,973) (22,374) (6,756)
--------- --------- --------- ---------
INCOME BEFORE EXTRAORDINARY LOSS 14,471 7,000 34,702 11,096
EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT
OF DEBT, net of minority interest and
income tax benefit of $473 -- -- (743) --
--------- --------- --------- ---------
NET INCOME $ 14,471 $ 7,000 $ 33,959 $ 11,096
========= ========= ========= =========
EARNINGS PER COMMON SHARE:
Income before extraordinary loss $ 51.32 $ 24.84 $ 123.06 $ 39.35
Extraordinary loss -- -- (2.64) --
--------- --------- --------- ---------
$ 51.32 $ 24.82 $ 120.42 $ 39.35
========= ========= ========= =========
</TABLE>
The accompanying notes to consolidated condensed financial statements
are an integral part of these consolidated statements.
4
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COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 1998 and 1997 (Unaudited)
(dollars in thousands)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
--------------------------
1998 1997
--------- --------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 33,959 $ 11,096
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization 31,382 31,583
Deferred income taxes 11,132 2,349
Extraordinary loss on early extinguishment of debt, non-cash portion 2,067 --
Minority interests in income, net of dividends (14,933) 2,522
Equity in net loss (income) of unconsolidated affiliates, net of dividends 7,232 (213)
Minimum lease payments received 22,242 --
Amortization of unearned lease income (23,567) --
Decrease (increase) in accounts receivable (6,410) 869
Decrease (increase) in inventories (2,392) 3,460
Decrease in accounts payable (3,479) (3,806)
Increase in accrued liabilities 3,073 2,444
Increase in other liabilities 1,557 6,806
Increase in other (30,134) (5,902)
--------- --------
Net cash flows provided by operating activities 31,729 51,208
--------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment additions (4,510) (1,591)
Decrease in marketable securities 42,118 12,684
Investments in affiliates (1,000) (53,443)
Acquisition of facilities, net of cash acquired (155,324) --
Decrease in restricted cash 9,868 2,179
--------- --------
Net cash flows used in investing activities (108,848) (40,171)
--------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt 192,310 2,618
Repayments of debt (155,673) (48,976)
Increase in deferred financing costs (1,713) (581)
Common stock dividend paid -- (5,000)
--------- --------
Net cash flows provided by (used in) financing activities 34,924 (51,939)
--------- --------
NET DECREASE IN CASH AND CASH EQUIVALENTS (42,195) (40,902)
CASH AND CASH EQUIVALENTS, beginning of period 71,833 89,188
--------- --------
CASH AND CASH EQUIVALENTS, end of period $ 29,638 $ 48,286
========= ========
</TABLE>
The accompanying notes to consolidated condensed financial statements
are an integral part of these consolidated statements.
5
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COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
UNAUDITED
1. Principles of Consolidation and Basis of Presentation
The accompanying unaudited consolidated condensed financial
statements include the accounts of Cogentrix Energy, Inc. and its wholly-owned
and majority-owned subsidiary companies (collectively, the "Company") and a
50%-owned joint venture in which the Company has effective control through
majority representation on the board of directors of the managing general
partner. Investments in other affiliates in which the Company has a 20% to 50%
interest and/or the ability to exercise significant influence over operating and
financial policies are accounted for on the equity method. All material
intercompany transactions and balances among Cogentrix Energy, Inc., its
subsidiary companies and its consolidated joint venture have been eliminated in
the accompanying consolidated condensed financial statements.
Information presented as of September 30, 1998 and for the three
months and nine months ended September 30, 1998 and 1997 is unaudited. In the
opinion of management, however, such information reflects all adjustments, which
consist of normal recurring adjustments necessary to present fairly the
financial position of the Company as of September 30, 1998, and the results of
operations for the three-month and nine-month periods ended September 30, 1998
and 1997 and cash flows for the nine months ended September 30, 1998 and 1997.
The results of operations for these interim periods are not necessarily
indicative of results which may be expected for any other interim period or for
the fiscal year as a whole.
The accompanying unaudited consolidated condensed financial
statements have been prepared pursuant to the rules and regulations of the
United States Securities and Exchange Commission. Certain information and note
disclosures normally included in annual financial statements prepared in
accordance with generally accepted accounting principles have been condensed or
omitted pursuant to those rules and regulations, although management believes
that the disclosures made are adequate to make the information presented not
misleading. These unaudited consolidated condensed financial statements should
be read in conjunction with the audited consolidated financial statements and
the notes thereto included in the Company's most recent Report on Form 10-K for
the Six-Month Transition Period Ended December 31, 1997, which was filed with
the United States Securities and Exchange Commission on March 31, 1998.
2. Cogentrix of Pennsylvania, Inc.
In January 1998, the Company signed an agreement with
Pennsylvania Electric Company ("Penelec") to terminate the Ringgold Facility's
power purchase agreement. This termination agreement was the result of a request
for proposals to buyback or restructure power sales agreements issued to all
major operating independent power producer projects in Penelec's territory in
April 1997. The termination agreement with Penelec provides for a payment to the
Company of approximately $24 million, which will be sufficient to retire all of
Cogentrix of Pennsylvania, Inc.'s ("CPA") outstanding project debt. The buyback
of the power purchase agreement is subject to the issuance of an order
(satisfactory to Penelec) by the Pennsylvania Public Utility Commission granting
Penelec the authority to fully recover from its customers the consideration paid
to CPA under the buyout agreement. Management does not expect the termination of
the Ringgold Facility's power purchase agreement with Penelec, if it occurs, to
have an adverse impact on the Company's consolidated results of operations, cash
flows or financial position.
3. James River Cogeneration Company
Effective February 1998, James River Cogeneration Company
("JRCC"), a joint venture owned 50% by the Company, which owns a cogeneration
facility located in Hopewell, Virginia (the "Hopewell Facility"), amended its
power sales agreement with Virginia Electric and Power Company ("Virginia
Power") to provide Virginia Power
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additional rights related to the dispatch of the Hopewell Facility. In
connection with the amendment of the power sales agreement, the Company amended
the terms of the existing project debt on the Hopewell Facility.
The amended terms of the JRCC project debt resulted in an
extension of the final maturity of the note payable by six months to December
31, 2002 and an increase in the amount of outstanding borrowings of $34.6
million, the proceeds of which (net of transaction costs) were distributed to
the JRCC partners. The amended note payable accrues interest at an annual rate
equal to the applicable LIBOR rate, as chosen by the Company, plus an additional
margin of .875% through February 1999 and 1.00% thereafter. The amended credit
facility also provides for a $5 million letter of credit to secure the project's
obligation to pay debt service. Cogentrix Energy, Inc. has indemnified the
lenders of the credit facility for any cash deficits the Hopewell Facility could
experience as a result of incurring certain costs, subject to a cap of $10.6
million. An extraordinary loss of $2.4 million was recorded in the first quarter
of 1998 related to the write-off of unamortized deferred financing costs from
the original project debt and a swap termination fee on an interest rate swap
agreement hedging the original project debt.
4. Whitewater and Cottage Grove Acquisition
In March 1998, the Company acquired from LS Power Corporation
(the "LS Power Acquisition") an approximate 74% ownership interest in two
partnerships which own and operate electric generating facilities located in
Whitewater, Wisconsin (the "Whitewater Facility") and Cottage Grove, Minnesota
(the "Cottage Grove Facility"). Each of the Cottage Grove and Whitewater
Facilities is a 245-megawatt gas-fired, combined-cycle cogeneration facility.
Commercial operations of both of these facilities commenced in the last half of
calendar 1997. The Cottage Grove Facility sells capacity and energy to Northern
States Power Company under a 30-year power sales contract terminating in 2027.
The Whitewater Facility sells capacity and energy to Wisconsin Electric Power
Company under a 25-year power sales contract terminating in 2022. Each of the
power sales contracts has characteristics similar to a lease in that the
agreement gives the purchasing utility the right to use specific property, plant
and equipment. As such, each of the power sales contracts is accounted for as a
"sales-type" capital lease in accordance with Statement of Financial Accounting
Standards ("SFAS") No. 13, "Accounting for Leases."
The aggregate acquisition price for the equity interests in the
Cottage Grove and Whitewater Facilities acquired by the Company was $158.0
million. In addition, the Company pre-funded a $16.7 million distribution to the
previous owners, which represented unused construction contingency and cash
flows that were accumulated by the Cottage Grove and Whitewater Facilities prior
to January 1, 1998. Cogentrix Energy, Inc. received $15.7 million of this
distribution in April 1998 and expects to receive a distribution of the
remaining $1 million in calendar 1998. The purchase price was funded with
proceeds of the Company's corporate credit facility and corporate cash balances.
The Company accounted for the LS Power Acquisition using the
purchase method of accounting. The accompanying consolidated balance sheet as of
September 30, 1998 reflects 100% of the assets and liabilities of the acquired
partnerships, consisting primarily of net investment in leases of $498.0 million
and long-term debt of $332 million, respectively. The minority owner's share of
each partnership's net assets is included in "minority interests" on the
accompanying consolidated balance sheet as of September 30, 1998. The
accompanying consolidated statements of income for the three months and nine
months ended September 30, 1998 include the results of operations of the
acquired facilities since the closing date of the LS Power Acquisition (March
20, 1998).
7
<PAGE> 8
The following unaudited pro forma consolidated results for the
Company for the nine months ended September 30, 1998 give effect to the LS Power
Acquisition as if the transaction had occurred on January 1, 1998 (in thousands,
except per share amount).
Pro Forma
Nine Months Ended
September 30, 1998
------------------
Revenues $ 336,938
Net Income $ 33,841
Earnings per share $ 120.00
5. Bechtel Asset Acquisition
In October 1998, the Company acquired from Bechtel Generating
Company, Inc. ("BGCI") ownership interests in 12 electric generating facilities,
comprising a net equity interest of approximately 365 megawatts, and one
interstate natural gas pipeline in the United States (the "BGCI Acquisition").
The aggregate acquisition price for the equity interests in the BGCI assets of
approximately $189 million is subject to adjustment either upward or downward
based on the final determination of the "Net Unrestricted Cash Differential" as
defined in the purchase agreement with BGCI. The BGCI Acquisition will be
accounted for using the purchase method of accounting. Management will account
for each of the underlying projects using the equity method.
In connection with the BGCI Acquisition, the Company issued $220
million of senior notes due 2008 in a Rule 144A offering (the "2008 Senior
Notes") with a covenant to register exchange notes with the U.S. Securities and
Exchange Commission. These senior notes are unsecured and rank pari passu with
the Company's $100 million of outstanding senior notes due 2004 (the "2004
Senior Notes"). The Company used the net proceeds to finance the BGCI
Acquisition and related transaction costs, to pay settlement costs for an
interest rate hedge agreement related to the offering of the 2008 Senior Notes.
6. Batesville Facility Acquisition
In August 1998, the Company acquired an approximate 52% interest
in an 800-megawatt, gas-fired electric generating facility (the "Batesville
Facility") under construction in Batesville, Mississippi (the "Batesville
Acquisition"). The Company has committed to provide an equity contribution to
the project subsidiary of approximately $54 million upon the earliest to occur
of (i) the incurrence of construction costs after all project financing has been
expended, (ii) an event of default under the project subsidiary's financing
arrangements and (iii) June 30, 2001. This equity commitment is supported by a
$54 million letter of credit provided under the Company's corporate credit
facility. The Company expects the Batesville Facility, which will be operated by
the Company, to commence commercial operation in June 2000. Electricity
generated by the Batesville Facility will be sold under long-term power purchase
agreements with two investment-grade utilities.
7. Pending Claims and Litigation
Effective September 1996, the Company amended the power sales
agreements on its Elizabethtown, Lumberton, Kenansville, Roxboro, and Southport
Facilities. Under the amended terms of these power sales agreements, the
purchasing utility has exercised its right of economic dispatch resulting in
significant reductions in fuel requirements at each of these facilities. In
response to this reduction in fuel requirements, one of the coal suppliers for
these facilities initiated an arbitration proceeding and another filed a civil
action against certain subsidiaries of the Company. The arbitration proceeding
was completed in October 1997, with the arbitration panel denying any recovery
to the coal supplier. The coal supplier subsequently challenged the arbitration
panel's ruling on grounds of partiality by the neutral arbitrator. On April 15,
1998, the federal district court issued an order vacating the arbitration award
and directing a new arbitration be conducted. The Company has appealed this
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<PAGE> 9
decision to the United States Court of Appeals for the Fourth Circuit. The
Company believes that the district court action was in error, that the
arbitration award is valid and will be upheld on appeal. With respect to the
civil action filed by the other coal supplier, we filed a motion to compel
arbitration of the contract claim, consented to, and filed a demand for,
arbitration of the claim. In March 1999, the dispute was submitted to
arbitration before a three-member panel of arbitrators. With one member of the
panel dissenting, the arbitrators ruled in favor of the coal supplier, awarding
approximately $8 million payable in 1999. Approximately $3 million of this award
relates to the reduction in purchase quantities for prior periods, and
approximately $5 million relates to a reduction in purchase quantities from the
date of the award through the balance of the term of the coal contract which
ends in September 2001. The future reduction in purchase quantities provides a
future economic benefit to the project subsidiary.
Effective December 1997, the Company amended the power sales
agreement on its Portsmouth Facility. Under the amended terms, the purchasing
utility has exercised its right of economic dispatch which has led to
significant reductions in that facility's fuel requirements. In response to the
reduced fuel requirements, the coal supplier for the Portsmouth Facility filed a
civil action in federal district court against a subsidiary of the Company. Upon
motion by the Company, the court has stayed the action pending arbitration of
the claims in Charlotte, North Carolina. On March 11, 1999, our project
subsidiary entered into a comprehensive settlement agreement with this coal
supplier, which is subject to the approval of the Company's and coal supplier's
board of directors and to the approval of the lenders to our project subsidiary.
The Company has established reserves which management believes to
be adequate to cover any expense resulting from these matters. Management
believes that the resolution of these disputes will not have a material adverse
effect on the consolidated financial position, results of operations or cash
flows of the Company.
8. Recently Issued Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities."
SFAS No. 133 establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheets as either an asset or
liability measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized in current earnings unless specified hedge
accounting criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company must formally document,
designate, and assess the effectiveness of transactions that receive hedge
accounting.
SFAS No. 133 is effective for fiscal years beginning after June
15, 1999. Early adoption is allowed. SFAS No. 133 must be applied to derivative
instruments and certain derivative instruments embedded in hybrid contracts that
were issued, acquired, or substantively modified after December 31, 1997.
The Company has not yet quantified the impacts of adopting SFAS
No. 133 on the consolidated financial statements and has not determined the
timing or method of adoption of SFAS No. 133. However, SFAS No. 133 could
increase volatility in earnings and other comprehensive income.
In April 1998, the American Institute of Certified Public
Accounts ("AICPA") issued Statement of Position ("SOP") No. 98-5, "Reporting on
the Costs of Start-Up Activities" which is effective for financial statements
for fiscal years beginning after December 15, 1998. SOP No. 98-5 requires costs
incurred for start-up activities to be expensed as incurred. For purposes of
this SOP, start-up activities are defined broadly as those one-time activities
related to opening a new facility, conducting business in a new territory,
conducting business with a new class of customer or beneficiary, initiating a
new process in an existing facility, or commencing a new operation. Start-up
activities include activities related to organizing a new entity (commonly
referred to as organization costs). The Company will adopt SOP No. 98-5 as of
January 1, 1999. The Company has not yet quantified the impact of SOP No. 98-5
on the consolidated financial statements.
9
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PART I - FINANCIAL INFORMATION
Item 1. Consolidated Condensed Financial Statements.
The information called for by this item is hereby incorporated
herein by reference to pages 3 through 9 of this report.
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
In addition to discussing and analyzing the Company's recent
historical financial results and condition, the following "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
includes statements concerning certain trends and other forward-looking
information affecting or relating to the Company which are intended to qualify
for the protections afforded "Forward-Looking Statements" under the Private
Securities Litigation Reform Act of 1995, Public Law 104-67. The forward-looking
statements made herein are inherently subject to risks and uncertainties which
could cause the Company's actual results to differ materially from the
forward-looking statements.
General
The Company is engaged in the acquisition, development,
ownership, and operation of electric generating facilities and the sale of
electricity and steam in the United States and selected international markets.
At December 31, 1997, the Company owned (entirely or in part) 11 electric
generating facilities having an aggregate generating capacity of 1,140
megawatts. In March 1998, the Company acquired ownership interests in two
gas-fired electric generating facilities in the Midwest United States having an
aggregate generating capacity of 490 megawatts. In August 1998, the Company
acquired an approximate 52% interest in an 800-megawatt, gas-fired electric
generating facility under construction in Batesville, Mississippi, which is
expected to be complete in June 2000. In October 1998, the Company acquired
BGCI's ownership interest in 12 electric generating facilities, comprising an
aggregate generating capacity of approximately 2,400 megawatts. Upon completion
of the construction of the Batesville Facility, the Company will have ownership
interests in a total of 26 domestic electric generating facilities with an
installed capacity of approximately 4,800 megawatts and a net equity interest in
such facilities of approximately 2,110 megawatts.
The Company's electric generating facilities produce electricity
for sale to utility customers and thermal energy, for sale to industrial users.
The electricity and thermal energy generated by these facilities are typically
sold under long-term power or steam sales agreements. Several of the Company's
electric generating facilities originally sold electricity under long-term,
"must-run" power sales agreements, which obligated the utility to purchase all
electricity generated by the facility. Over the last two years, the Company has
negotiated amendments to the majority of these "must-run" power sales agreements
to provide the utility the ability to suspend or reduce purchases of energy from
the facilities if the utility determines it can operate its system for a
designated period more economically. These amended power sales agreements are
structured so that the Company continues to receive capacity payments during any
period of economic dispatch. Capacity payments cover project debt service and
fixed operating costs and constitute a substantial portion of the profit
component of the power sales agreement. Energy payments, which are reduced (or
possibly eliminated) as a result of economic dispatch, primarily cover variable
operating and maintenance costs as well as fuel and fuel transportation costs.
The restructuring of a "must-run" power sales agreement to an economic dispatch
power sales agreement causes a significant reduction in electric revenues
recognized under the contract, which is offset by a corresponding reduction in
fuel and fuel transportation costs and operations and maintenance expense. In
response to the reduction in fuel requirements at certain of the facilities at
which the Company has restructured the power sales agreement, the facilities'
coal suppliers have instituted various legal proceedings against the Company
seeking to recover damages. See "Part II-Item I. - Legal Proceedings" herein.
The power sales agreements at seven of the Company's facilities
either terminate in years 2000 through 2002 or provide for a significant
reduction in capacity payments received under such agreements after 2002.
Accordingly, revenues recognized by the Company under these power sales
agreements after 2002 will be
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eliminated or significantly reduced. The Company believes, however, that its
project subsidiaries and unconsolidated affiliates will generate sufficient cash
flow to allow them to pay management fees and dividends to Cogentrix Energy,
Inc. ("Cogentrix Energy") periodically in sufficient amounts to allow Cogentrix
Energy to pay all required debt service on its 2004 Senior Notes and 2008 Senior
Notes (collectively, the "Senior Notes"), pay all required debt service on its
corporate credit facility, fund a significant portion of the Company's
development activities and permit the Company to meet its other obligations.
In March 1998, the Company acquired ownership interests in two
gas-fired electric generating facilities located in the Midwest United States
having an aggregate generating capacity of 490 megawatts. The power sales
agreements for these facilities meet the criteria of a "sales-type" capital
lease as described in SFAS No. 13, "Accounting for Leases." The Company has
recorded a net investment in lease which reflects the present value of future
minimum lease payments. Future minimum lease payments represent the amount of
capacity payments due from the utilities under the power sales agreements in
excess of fixed operating costs (i.e., executory costs). The difference between
the undiscounted future minimum lease payments due from the utilities and the
net investment in lease represents unearned income. This unearned income will be
recognized as lease revenue over the term of the power sales agreements using
the effective interest rate method. The Company also recognizes service revenue
related to the reimbursement of costs incurred in operating the facilities to
generate electricity and thermal energy. The amount of service revenue
recognized by the Company is directly related to the level of dispatch of the
facilities by the utilities and to a lesser extent the level of thermal energy
required by the steam hosts.
In August 1998, the Company acquired an approximate 52% ownership
interest in the Batesville Facility. The Company expects the Batesville
Facility, which will be operated by the Company, to commence commercial
operation in June 2000. Electricity generated by the Batesville Facility will be
sold under long-term power purchase agreements with two investment-grade
utilities.
In October 1998, the Company acquired BGCI's ownership interests,
which range from 3.3% to 49%, in 12 electric generating facilities and BGCI's
0.5% ownership interest in an interstate natural gas pipeline (the "BGCI
Assets"). The acquisition of the BGCI Assets provides the Company with a net
equity interest of approximately 365 megawatts in a diverse generating portfolio
that comprises approximately 2,400 megawatts in total generating capacity. The
BGCI Acquisition will be accounted for using the purchase method of accounting.
Management will account for each of the underlying projects using the equity
method.
The activities of the Company's electric generating facilities
are subject to stringent environmental regulations by federal, state, local and
(for future non-U.S. projects) foreign governmental authorities. The Clean Air
Act Amendments of 1990 require states to impose permit fees on certain
emissions, and Congress may consider proposals to restrict or tax certain
emissions, which proposals, if adopted, could impose additional costs on the
operation of the Company's facilities. There can be no assurance that the
Company's business and financial condition would not be materially and adversely
affected by the cost of compliance with future changes in domestic or foreign
environmental laws and regulations or additional requirements for reduction or
control of emissions imposed by regulatory authorities in connection with
renewals of required permits. The Company maintains a comprehensive program to
monitor its project subsidiaries' compliance with all applicable environmental
laws, regulations, permits and licenses.
The domestic electric generating industry is currently going
through a period of significant change as many states are implementing or
considering regulatory initiatives designed to increase competition. In addition
to restructuring activities in various states, there have also been several
industry restructuring bills introduced in Congress. The Company cannot predict
the final form or timing of the proposed restructurings and the impact, if any,
that such restructurings would have on the Company's existing business or
consolidated results of operations. The Company believes that any such
restructuring would not have a material adverse effect on its power sales
agreements and, accordingly, believes that its existing business and results of
consolidated operations would not be materially adversely affected, although
there can be no assurance in this regard.
In 1996, the Company began making investments in partnerships
formed to develop, construct and operate greenhouses to produce tomatoes. These
partnerships are currently operating greenhouses with a combined total of
11
<PAGE> 12
107 acres of production capacity. The Company has a 50% interest in each
partnership and accounts for these investments under the equity method.
Results of Operations - Three Months and Nine Months Ended September 30, 1998
and 1997
<TABLE>
<CAPTION>
Three Months Ended September 30, Nine Months Ended September 30,
----------------------------------------- ------------------------------------------
1998 1997 1998 1997
----------------- ---------------- ----------------- ------------------
(dollars in thousands, unaudited)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total operating revenues $122,672 100% $91,532 100% $317,528 100% $263,189 100%
Operating costs 54,904 45 47,895 52 141,439 44 143,993 55
General, administrative
and development 8,613 7 8,139 9 27,765 9 31,547 12
Depreciation and
amortization 10,767 9 10,238 11 31,382 10 31,583 12
-------- --- ------- --- -------- --- -------- ---
Operating income $ 48,388 39% 399,000 28% $116,942 37% $ 56,066 21%
======== === ======= === ======== === ======== ===
</TABLE>
Total operating revenues increased 34.0% to $122.7 million for
the third quarter of 1998 as compared to the third quarter of 1997. This
increase was primarily attributable to the $23.8 million aggregate amount of
lease revenue and service revenue earned under the power sales agreements for
the Cottage Grove and Whitewater Facilities in which the Company acquired its
interests in March 1998. The increase in operating revenues is also related to a
$4.3 million construction management fee received in August 1998. This
construction management fee relates to cost savings realized on the completion
of construction of a 248 megawatt gas-fired electric generating facility (the
"Clark Facility") for Public Utility District Number 1 of Clark County,
Washington. Electric revenue for the third quarter of 1998 also increased 3.0%
as compared to the same period for fiscal 1997,as a result of an increase in
megawatt hours sold to the purchasing utility at the Lumberton, Rocky Mount,
Richmond and Southport Facilities. This increase in electric revenue was
partially offset, however, by a $1.3 million decrease in electric revenue
resulting from the restructuring of the Company's power sales agreements on the
Portsmouth Facility in December 1997 and the Hopewell Facility in February 1998
to give the purchasing utility the right to suspend or reduce purchases of
energy from the facilities.
The Company's operating revenues for the nine-month period ended
September 30, 1998, which increased 20.6% to $317.5 million as compared to
$263.2 million for the nine-month period ended September 30, 1997, were largely
influenced by the same factors discussed above: the acquisition of the Cottage
Grove and Whitewater Facilities, the construction management fee received in
August 1998 related to the Clark Facility, an increase in megawatts sold at the
Lumberton, Rocky Mount, Richmond and Southport Facilities and the restructuring
of the Company's power sales agreements on the Portsmouth and the Hopewell
Facilities.
The Company's operating costs increased 14.6% to $54.9 million
for the third quarter of 1998 as compared to the third quarter of 1997. This
increase resulted primarily from the $14.0 million in cost of services incurred
by the Cottage Grove and Whitewater Facilities, interests in which the Company
acquired in March 1998. Operating expenses were also impacted by the increases
in fuel expense at the Rocky Mount and Richmond Facilities associated with an
increase in megawatt hours sold and routine maintenance expenses at the Rocky
Mount and Southport Facilities. The increases in operating expenses were
partially offset by a significant reduction in fuel expense at the Portsmouth
and Hopewell Facilities associated with the restructuring of their power sales
agreements. The increase in operating expenses was also offset by decreases in
operating costs incurred by ReUse Technology, Inc, a wholly-owned subsidiary of
the Company ("ReUse"), related to third-party agreements.
The Company's operating costs for the nine-month period ended
September 30, 1998 decreased 1.8% to $141.4 million as compared to $144.0
million for the nine-month period ended September 30, 1997. The decrease
resulted from a significant decrease in the fuel expense at the Hopewell and
Portsmouth Facilities as a result of the restructuring of their power sales
agreements, and a reduction in operating costs at ReUse. The decrease in
operating expenses for the nine month period ended September 30, 1998 was
partially offset by some of the same
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<PAGE> 13
factors discussed above: increases in operating costs related to the acquisition
of the Cottage Grove and Whitewater Facilities, increase in the fuel expense at
the Richmond and Rocky Mount Facilities associated with an increase in megawatt
hours sold, and an increase in routine maintenance expense at the Rocky Mount
Facility.
General, administrative and development expenses increased 5.8%
to $8.6 million for the third quarter of 1998 as compared to the corresponding
period of 1997. The increase was primarily the result of expenses related to the
Company's project development efforts.
General, administrative and development expenses for the
nine-month period ended September 30, 1998 decreased 12.0% to $27.8 million as
compared to $ 31.5 million for the nine-month period ended September 30, 1997.
The decrease was primarily the result of $10.7 million of expense recognized in
the nine-month period ended September 30, 1997 related to the restructuring or
terminating of incentive compensation arrangements for certain employees, as
well as expense incurred related to severance payments to certain executive
officers. The decrease was also due to a general decrease in salary expense
during the nine-month period ended September 30, 1998 as a result of a
restructuring completed by the Company in the prior year. This decrease was
partially offset by an increase in incentive compensation expense related to the
Company's profit-sharing plan as a result of the increase in the Company's
profitability for the nine-month period ended September 30, 1998, and expenses
incurred related to the Company's project development efforts .
Interest expense increased 42.7% to $19.0 million for the third
quarter of 1998 and 25.5% to $52.0 million for the nine-month period ended
September 30, 1998 as compared to the corresponding periods of 1997. The
Company's average long-term debt increased to $968 million, with a weighted
average interest rate of 7.27%, for the third quarter of 1998 as compared to
average long-term debt of $700 million, with a weighted average interest rate of
7.9%, for the third quarter of 1997. The increases in interest expense and
weighted average debt outstanding are related to the inclusion of the project
finance debt of the Cottage Grove and Whitewater Facilities acquired in March
1998 and the increase in project finance debt outstanding at the Portsmouth
Facility, which was refinanced in December 1997, and the Hopewell Facility,
which was refinanced in February 1998. The increases also related to outstanding
borrowings under the corporate credit facility. The increase in interest expense
discussed above was partially offset by a decrease in interest expense at
several of the Company's project subsidiaries due to the scheduled amortization
of outstanding project finance debt. The decrease in weighted average interest
rate related primarily to the expiration of an interest rate swap agreement on
the Richmond Facility's project debt in September 1997, a decrease in the LIBOR
rate during the period for a portion of the Company's debt that is subject to
floating rate fluctuations, and the refinancing of the project debt at the
Portsmouth and Hopewell Facilities on more favorable interest rate terms.
The increase in the equity in net loss of affiliates for the
three-month and nine-month periods ended September 30, 1998, relates to an
increase in losses recognized by the partnerships operating tomato greenhouses
in the states of New York and Texas. These losses result from the delayed
start-up of the New York greenhouse and production problems experienced at the
Texas greenhouses. In addition, the tomato market has experienced lower than
normal pricing due primarily to increased competition.
The increase in minority interests in income for the three-month
and nine-month periods ended September 30, 1998 as compared to the corresponding
periods of the prior year relates to the recognition of the minority partner's
share of earnings in the Cottage Grove and Whitewater Facilities, and an
increase in earnings at the Hopewell Facility as a result of that facility's
restructured power sales agreement.
The extraordinary loss on early extinguishment of debt for the
nine-month period ended September 30, 1998 related to the refinancing of the
Hopewell Facility's project debt in January 1998. The loss consisted of a
write-off of the deferred financing costs on the Hopewell Facility's original
project debt and a swap termination fee on an interest rate swap agreement
hedging the original project debt.
13
<PAGE> 14
Liquidity and Capital Resources
The principal components of operating cash flow for the
nine-month period ended September 30, 1998 were net income of $33.7 million,
increases due to adjustments for depreciation and amortization of $30.9 million,
deferred income taxes of $11.0 million, a write-off of deferred financing costs
of $2.1 million and equity in net income (loss) of unconsolidated affiliates,
net of dividends of $7.2 million, which were partially offset by amortization of
unearned lease income, net of minimum lease payments received of $1.3 million,
minority interests in income, net of dividends, of $14.9 million and a net $15.6
million use of cash reflecting changes in other working capital assets and
liabilities. Cash flow provided by operating activities of $53.1 million,
proceeds from borrowings of $170.9 million, proceeds from the sale of marketable
securities of $42.1 million, and $9.8 million of cash escrows released were
primarily used to acquire interests in facilities of $155.3 million, purchase
property plant and equipment of $4.5 million, make investments in affiliates of
$1.0 million, repay project finance borrowings of $155.6 million, and pay
deferred financing costs of $1.7 million.
Historically, the Company has primarily financed each facility
under financing arrangements and related documents which generally require the
extensions of credit to be repaid solely from the project's revenues and provide
that the repayment of the extensions of credit (and interest thereon) be secured
solely by the physical assets, agreements, cash flows and, in certain cases, the
capital stock of or partnership interest in that project subsidiary. This type
of financing is generally referred to as "project financing." The project
financing debt of the Company's subsidiaries (aggregating $919.6 million as of
September 30, 1998) is substantially non-recourse to the Company and its other
project subsidiaries, except in connection with certain transactions where
Cogentrix Energy or Cogentrix, Inc. ("Cogentrix") has agreed to certain limited
guarantees and other obligations with respect to such projects. These limited
guarantees and other obligations include agreements for the benefit of the
project lenders to three project subsidiaries to fund cash deficits the projects
may experience as a result of incurring certain costs, subject to an aggregate
cap of $51.9 million. In addition, Cogentrix has guaranteed certain project
subsidiaries' obligations to the purchasing utility under power sales
agreements. Because certain of these limited guarantees and other obligations do
not by their terms stipulate a maximum dollar amount of liability, the aggregate
amount of the Company's potential exposure under these guarantees cannot be
quantified. The aggregate contractual liability of the Company to its
subsidiaries' project lenders is, in each case, a small portion of the aggregate
project debt. If, however, the Company were required to satisfy all these
guarantees and other obligations, or even one or more of the significant ones,
such event could have a material adverse impact on the Company's financial
condition.
Any projects the Company develops in the future, and those
independent power projects it may seek to acquire, are likely to require
substantial capital investment. The Company's ability to arrange financing on a
substantially non-recourse basis, acquisition financing, and the cost of such
capital are dependent on numerous factors. In order to access capital on a
substantially non-recourse basis in the future, the Company may have to make
larger equity investments in, or provide more financial support for, the project
entity.
The ability of the Company's project subsidiaries and the project
entities in which it has an investment to pay dividends and management fees
periodically to Cogentrix Energy is subject to certain limitations in their
respective project credit documents. Such limitations generally require that:
(i) project debt service payments be current, (ii) project debt service coverage
ratios be met, (iii) all project debt service and other reserve accounts be
funded at required levels and (iv) there be no default or event of default under
the relevant project credit documents. There are also additional limitations
that are adapted to the particular characteristics of each project subsidiary
and project entity in which the Company has an investment. Management does not
believe that such restrictions or limitations will adversely affect its ability
to meet its debt obligations.
As of September 30, 1998, the Company had long-term debt
(including the current portion thereof) of approximately $1.0 billion. With the
exception of the Company's $100 million of 2004 Senior Notes, substantially all
of such indebtedness is project financing debt that is substantially
non-recourse to the Company. Future annual maturities of long-term debt range
from $78.1 million to $90.0 million in the five-year period ending December 31,
2002. The Company believes that its project subsidiaries and the project
entities in which it has an investment will generate sufficient cash flow to pay
all required debt service on the project financing debt and allow them to pay
management fees and/or dividends to Cogentrix Energy periodically in sufficient
amounts to allow Cogentrix
14
<PAGE> 15
Energy to pay all required debt service on outstanding balances under the
corporate credit facility and on the Senior Notes, fund a significant portion of
its development activities and meet its other obligations. If, as a result of
unanticipated events, the Company's ability to generate cash from operating
activities is significantly impaired, the Company could be required to curtail
its development activities to meet its debt service obligations.
In May 1997, the Company entered into a credit agreement with
Australia and New Zealand Banking Group Limited, as agent for a group of lending
banks (the "Corporate Credit Facility"), which provides for a $50 million
revolving credit facility with a term of three years ('Revolving Term"). In
October 1998, the Company amended and restated the Corporate Credit Facility
to provide for direct advances to, or the issuance of letters of credit for, the
benefit of the Company in an amount up to $100 million. The Corporate Credit
Facility is unsecured and imposes covenants on the Company substantially the
same as the covenants contained in the indentures for the Company's Senior
Notes, as well as certain financial condition covenants. The Company used
approximately $54 million of the credit availability under the Corporate Credit
Facility for the letter of credit issued in connection with the Batesville
Acquisition. The balance of the commitment under the Corporate Credit Facility
is available, subject to any limitations imposed by the covenants contained
therein and in the indentures for the Senior Notes, to be drawn upon by the
Company to repay other outstanding indebtedness or for general corporate
purposes, including equity investments in new projects or acquisitions of
existing electric generating facilities or those under development.
In December 1997, the Company substantially completed
construction of a 248-megawatt combined-cycle, gas-fired electric generating
facility (the "Clark Facility") for Public Utility District Number 1 of Clark
County, Washington ("Clark") and earned a construction management fee of $4.5
million. In August 1998, the Company earned an additional $4.3 million, which
represents an additional construction management fee of $0.5 million and the
Company's share ($3.8 million) of cost savings in constructing the Clark
Facility.
In December 1997, the Company renegotiated the project financing
arrangements for its Portsmouth Facility. The amended agreements resulted in an
extension of the final maturity date of the loan by three months and an increase
in the amount of commitment provided by the project lenders in the form of a
$40.5 million revolving credit facility. This revolving credit facility is
available to be drawn by Cogentrix Virginia Leasing Corporation, the project
subsidiary owning the Portsmouth Facility ("CVLC"), at any time for general
corporate purposes, including paying dividends to Cogentrix Energy. In March
1998, CVLC borrowed $20 million under the revolving credit facility and
distributed the entire proceeds to Cogentrix Energy for purposes of funding a
portion of the purchase price related to the LS Power Acquisition. In July 1998,
the project subsidiary borrowed an additional $20.5 million and distributed it
to the Company for purposes of paying down the outstanding balance under the
Corporate Credit Facility.
In February 1998, the Company renegotiated the project financing
arrangements for its Hopewell Facility, in which it owns a 50% interest. The
amended agreements resulted in a $34.6 million increase in outstanding
indebtedness of JRCC and extended the final maturity date of the loan by six
months. JRCC transferred substantially all of the additional funds borrowed (net
of transaction costs) to its partners. The distribution received by Cogentrix
Energy related to the refinancing was approximately $16.6 million, which was
used by the Company to fund a portion of the acquisition price related to the LS
Acquisition.
In March 1998, the Company acquired from LS Power Corporation an
approximate 74% ownership interest in the Whitewater Facility and the Cottage
Grove Facility. Each of the Cottage Grove and Whitewater Facilities is a
245-megawatt gas-fired, combined-cycle cogeneration facility. Commercial
operations of both facilities commenced in the last half of calendar 1997. The
aggregate acquisition price for the equity interests in the Cottage Grove and
Whitewater Facilities acquired by the Company was $158.0 million. In addition,
the Company pre-funded a $16.7 million distribution to the previous owners,
which represented unused construction contingency and cash flows that were
accumulated by the Cottage Grove and Whitewater Facilities prior to January 1,
1998. Cogentrix Energy received a distribution of $15.7 million in April 1998
and expects to receive a distribution of the remaining $1.0 million in 1998. The
purchase price was funded with borrowings under the Corporate Credit Facility
and corporate cash balances.
15
<PAGE> 16
In August 1998, the Company acquired an approximate 52% interest
in the Batesville Facility. The Company has committed to provide an equity
contribution to the project subsidiary of approximately $54 million upon the
earliest to occur of (i) the incurrence of construction costs after all project
financing has been expanded, (ii) an event of default under the project
subsidiary's financing arrangements and (iii) June 30, 2001. This equity
commitment is supported by a $54 million letter of credit, which is provided
under the Corporate Credit Facility. The Company expects the Batesville
Facility, which will be operated by the Company, to commence commercial
operation in June 2000.
In October 1998, the Company acquired Bechtel Generating Company,
Inc.'s ownership interests in 12 electric generating facilities, comprising a
net equity interest of approximately 365 megawatts, and one interstate natural
gas pipeline. The aggregate acquisition price for the ownership interests,
including acquisition costs, was approximately $189.9 million. The purchase
price was funded with a portion of the proceeds from the sale of $255 million of
senior notes due 2008.
As a result of a March 1999 arbitration award related to a
contract dispute with a coal supplier, the Company is obligated to pay
approximately $8 million in 1999. Approximately $3 million of this award relates
to the reduction in purchase quantities for prior periods and approximately $5
million relates to the reduction in purchase quantities from the date of the
award through the balance of the term of the coal contract, which ends in
September 2001. The future reduction in purchase quantities provides a future
economic benefit to the project subsidiary. The amount of damages awarded will
not materially reduce the projected amount of cash flow to Cogentrix Energy for
the current fiscal year and should not, therefore, have a material adverse
impact on Cogentrix Energy's ability to service its outstanding debt.
For the fiscal year ended June 30, 1997, the Company's board of
directors declared a dividend on its outstanding common stock of $5.0 million,
which was paid in September 1997. The Company's board of directors declared a
dividend on its outstanding common stock of $2.1 million for the six-month
period ended December 31, 1997, which was paid in March 1998. The board of
directors' policy, which is subject to change at any time, provides for a
dividend payout ratio of no more than 20% of the Company's net income for the
immediately preceding fiscal year. In addition, under the terms of the
indentures for the Senior Notes and the credit agreement for the Corporate
Credit Facility, the Company's ability to pay dividends and make other
distributions to its shareholders is restricted.
Impact of Energy Price Changes, Interest Rates and Inflation
Energy prices are influenced by changes in supply and demand, as
well as general economic conditions, and therefore tend to fluctuate
significantly. Through various hedging mechanisms, the Company has attempted to
mitigate the impact of changes on the results of operations of most of its
projects. The basic hedging mechanism against increased fuel and transportation
costs is to provide contractually for matching increases in the energy payments
the Company's project subsidiaries receive from the utility purchasing the
electricity generated by the facility.
Under the power sales agreements for certain of the Company's
facilities, energy payments are indexed (subject to certain caps) to reflect the
fuel cost of producing electricity. The Company's other power sales agreements
provide periodic, scheduled increases in energy prices that are designed to
match periodic, scheduled increases in fuel and transportation costs that are
included in the fuel supply and transportation contracts for the facilities.
Changes in interest rates could have a significant impact on the
Company. Interest rate changes affect the cost of capital needed to construct
projects, as well as interest expense of existing project financing debt. As
with fuel price escalation risk, the Company attempts to hedge against the risk
of fluctuations in interest rates by arranging either fixed-rate financing or
variable-rate financing with interest rate swaps, collars or caps on a portion
of its indebtedness.
Although hedged to a significant extent, the Company's financial
results will likely be affected to some degree by fluctuations in energy prices,
interest rates and inflation. The effectiveness of the hedging techniques
implemented by the Company is dependent, in part, on each counterparty's ability
to perform in accordance with the provisions of the relevant contracts. The
Company has sought to reduce the risk by entering into contracts with
creditworthy organizations.
16
<PAGE> 17
Year 2000 Compliance
The Year 2000 issue exists because many computer systems and
applications, including those embedded in equipment and facilities, use two
digit rather than four digit date fields to designate an applicable year. As a
result, the systems and applications may not properly recognize the year 2000
or process data which includes such date, potentially causing data
miscalculations or inaccuracies or operational malfunctions or failures.
Cogentrix initiated assessments in 1997 to identify the issues required to be
resolved to assure business critical systems successfully operate upon and
beyond the turn of the century. The assessments include reviewing information
technology and systems utilizing embedded technology. Plans for achieving Year
2000 compliance were finalized during 1998 and remediation work is underway. We
have identified the following systems and applications to focus our efforts to
ensure Year 2000 compliance:
- corporate applications, which include core business systems;
- embedded technology systems, which include the plants
operating and control systems and
- business partner and vendor systems.
Non-compliance in the embedded technology systems or business partner and
vendor systems could result in temporary shutdown of the facilities, and
potential equipment damage.
Replacement of our core financial systems which include
corporate applications such as purchasing, accounts payable and general ledger,
with Year 2000 compliant client-server software is virtually complete. We
expect to complete the updating of our human resources and internal payroll
systems by June 30, 1999. We do not expect any disruptions in corporate
applications as a result of the Year 2000 issue.
Investigation, analysis, remediation and contingency planning
for embedded technology such as plant operating control systems,
telecommunications and facilities-based equipment at all of our power
generation facilities have been completed. The investigation and analysis have
identified no significant Year 2000 issues. For those insignificant issues that
have been identified as non-compliant, we have established a remediation plan
to address the areas of non-compliance. The remediation of these systems is
expected to be completed by June 30, 1999. The costs to replace our core
financial systems, update our human resources and internal payroll systems and
bring the operating systems at the plant facilities fully compliant with Year
2000 are currently expected to be approximately $2.8 million, of which $2.4
million has already been incurred.
We are communicating with critical suppliers, vendors, joint
venture partners and major customers verbally, in writing and through other
representations made by the organizations to assess their compliance efforts
and our exposure resulting from Year 2000 issues. Of major concern to us are
the fuel suppliers and transporters,and the electric and steam customers. We
produce revenue by selling the power we produce to major utilities. We depend
on fuel suppliers and transporters to deliver our fuel to power the generating
facilities. We also rely on transmission and distribution facilities to deliver
our power to the electric and steam customers. At this time, based on our
review of responses we have received, we do not expect a major impact from
non-compliant Year 2000 suppliers, vendors joint venture partners or major
customers. However, an incomplete or incorrect assessment of the Year 2000
issues by the suppliers and transporters, transmission and distribution
facilities, as well as the utility customers, could adversely effect our
financial results and operations.
We have developed contingency plans for the critical systems. We
developed these plans to address our most likely worst case scenario, the
inability of our plants to produce and distribute power. The contingency plans
include turning back the date on all date critical systems at the plant to
ensure the continuous operation of the generating facilities. These plans have
been tested and appear to be adequate.
We expect that our business critical systems will be Year 2000
compliant by December 31, 1999, and we do not anticipate costs associated with
the Year 2000 issue to have a material impact on our consolidated results of
17
<PAGE> 18
operations or financial position. Currently, we have not entered into any
material contracts with external contractors to complete the Year 2000
compliance projects. We have dedicated two headquarters level employees to
oversee, develop and test systems to ensure Year 2000 readiness. Managers at
each plant location are also responsible for various components of the Year
2000 testing. Despite management's current expectations, there can be no
assurances that there will not be interruptions or other limitations of
financial and operating systems functionality or that we will not ultimately
incur significant unplanned costs to avoid such interruptions or limitations.
Change of Corporate Fiscal Year
Effective January 1, 1998, the Company changed its fiscal year to
commence on January 1 and conclude on December 31 of each year. The Company's
fiscal year previously commenced each July 1, concluding on June 30 of the
following calendar year.
18
<PAGE> 19
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
COGENTRIX ENERGY, INC.
(Registrant)
March 17, 1999 /s/ Thomas F. Schwartz
-------------------------------------
Thomas F. Schwartz
Senior Vice President - Finance
Treasurer
(Principal Financial and Accounting
Officer)
19
